The present invention relates to a method for controlling fluid loss from a subterranean formation. More specifically, the present invention relates to methods for controlling the loss of well treatment fluids, such as fluids used for stimulating production of hydrocarbons from such formations, fluids used for diverting the flow of fluids, fluids used for controlling water production, pad stages for conventional propped fracturing treatments, solvent treatments, and in general, any fluid used in treating a formation.
The flow of fluids through porous media, for example the production of fluids from wells, is governed by three principle factors: the size of the flow path, the permeability of the flow path, and the driving force. It is often necessary to stimulate the production of fluids from subterranean formations when wells are not producing satisfactorily. The failure to produce is typically due to an inadequate, or a damaged, path for fluids to flow from the formation to the wellbore. This damage may be because the formation inherently has insufficient porosity and/or permeability, or because the porosity and/or permeability have been decreased (damaged) near the wellbore during drilling and/or completion and/or production.
There are two main stimulation techniques: matrix stimulation and fracturing. Matrix stimulation is accomplished by injecting a fluid (e.g., acid or solvent) to dissolve and/or disperse materials that impair well production or to create new, unimpaired flow channels between the wellbore and a formation. Matrix stimulation, typically called matrix acidizing when the stimulation fluid is an acid, generally is used to treat only the near-wellbore region. In a matrix acidizing treatment, the acid used (typically hydrochloric acid for carbonate formations) is injected at a pressure low enough to prevent fracturing the formation.
When acid is pumped into a subterranean formation, such as a carbonate (for example, limestone or dolomite) formation, at pressures below the fracture pressure, the acid flows preferentially into the highest solubility or the highest permeability (that is, largest pores, vugs or natural fractures) regions. Acid reaction in the high-solubility or high-permeability region ideally causes the formation of large, highly conductive flow channels called wormholes that form approximately radially from the wellbore. However, acid that enters vugs or natural fractures may be substantially wasted, and low permeability regions may be untreated.
In fracturing, on the other hand, a fluid is forced into the formation at a pressure above that at which the formation rock parts to create an enlarged flow path. When the pressure is released, the fracture typically closes and the new flow path is not maintained unless the operator provides some mechanism by which the fracture is held open. There are two common ways of holding the fracture open. In conventional propped hydraulic fracturing, a viscous fluid (pad stage) is injected to generate or propagate a fracture. Subsequent stages of viscous fluid carry solid proppant that is trapped in the fracture when the pressure is released, preventing the fracture from fully closing. In acid fracturing, also known as fracture acidizing, the fracture is generated and subsequently treated with an acid. In this case, however, the treatment parameters are commonly adjusted so that wormholing does not occur. Instead, the object is to etch the faces of the fracture differentially. Then, when the pressure is released, the fracture does not close completely because the differential etching has created a gap, or non-matching uneven surfaces, where material has been removed. Ideally the differential etching forms flow channels, usually running along the faces of the fracture from the tip to the wellbore, that enhance production.
Although the following discussion will focus for the most part on matrix acidizing (treatment with formation dissolving fluids (FDF's), not all of which are acids), similar problems affect matrix stimulation, hydraulic fracturing with proppants, acid fracturing, and other methods, such that this discussion is entirely applicable to all types of formation treatment fluids (FTF's). Note that FDF's are a subset of FTF's, and that, as defined here, FDF's include fluids that dissolve the formation or damage in the formation, such as scale and invaded drilling fluids.
A problem that limits the effectiveness of FTF's is incomplete axial distribution. This problem relates to the proper placement of the fluid, i.e., ensuring that the fluid is delivered to the desired zone (i.e., the zone that needs treatment) rather than another zone. More particularly, when an acid is injected into a carbonate formation, the acid typically begins to dissolve the material in the wellbore and/or the matrix near the wellbore. Depending upon the reactivity of the acid with the matrix and the flow rate of acid to the reaction location, as one continues to pump acid into the formation, a dominant channel through the matrix is often created. As one continues to pump acid into the formation, the acid flows along that newly created channel as the path of least resistance and therefore leaves the rest of the formation substantially untreated. This behavior is exacerbated by the intrinsic permeability heterogeneity (common in many formations) of the formation, especially the presence of natural fractures and high permeability streaks in the formation. These regions of heterogeneity attract large amounts of the injected acid, hence keeping the acid from reaching other parts of the formation along the wellbore where it is actually desired most. Thus, in naturally fractured reservoirs, a substantial portion of the productive, oil- or gas-bearing intervals within the zone to be treated are not contacted by acid sufficient to penetrate deep enough (laterally in the case of a vertical wellbore) into the formation matrix to effectively increase formation permeability, and therefore its capacity for delivering oil and/or gas to the wellbore. This problem of proper placement is particularly vexing since the injected fluid preferentially migrates to higher permeability zones (the path of least resistance) rather than to lower permeability zones, yet it is those latter zones that generally require the acid treatment (i.e., because they are low permeability zones, the flow of oil and/or gas through them is diminished). In response to this problem, numerous techniques have been developed to achieve more controlled placement of the fluid, diverting the acid away from naturally high permeability zones, and zones already treated, to the regions of interest.
Techniques to control acid leakoff (i.e., to ensure effective zone coverage) can be roughly divided into either mechanical or chemical techniques. Mechanical techniques include ball sealers (balls dropped into the wellbore to plug the perforations in the well casing, thus sealing the perforation against fluid entry), packers (particularly straddle packers that seal off portion of the wellbore and thereby prevent fluid entry into the perforations in that portion of the wellbore) and bridge plugs, coiled tubing (flexible tubing deployed by a mechanized reel, through which the acid can be delivered to a more precise location within the wellbore), and bullheading (attempting to achieve diversion by pumping the acid at the highest possible pressure-just below the pressure that would actually fracture the formation). Chemical techniques can be further divided into techniques that chemically modify the wellbore adjacent the portions of the formation for which acid diversion is desired, and techniques that modify the acid-containing fluid itself. The first type involves particulate materials that form a reduced-permeability cake on the wellbore face that, upon contact with the acid, diverts the acid to lower permeability regions. These materials are typically either oil-soluble or water-soluble particulates that are directed at the high permeability zones to plug them and therefore divert acid flow to the low permeability zones. The second type includes foaming agents, emulsifying agents, and gelling agents. Mechanical methods and chemical methods that chemically modify the wellbore adjacent portions of the formation for which acid diversion is desired will not be considered further here.
Emulsified acid systems and foamed systems are commercially available responses to the diversion problem, but operational complexity sometimes limits their use. For instance, friction pressures may be high. In addition, these fluids are not effective at diverting fluids from natural fractures. Gelling agents are commercially available, but do not provide viscosity contrasts sufficient to provide fluid diversion from natural fractures. Some commercially available systems are polymeric cross-linked systems, i.e., they are linear polymers when pumped, but a chemical agent pumped along with the polymer causes the polymers to aggregate or cross-link once in the formation (e.g., due to a change in pH caused by reaction of the acid), which results in gelling. Although these in situ cross-linked polymer fluids can be effective in controlling fluid loss through wormholes, they are ineffective at controlling losses through natural fractures. In addition, these systems leave a polymer residue in the formation, which can damage the formation, resulting in diminished hydrocarbon production.
The use of viscoelastic surfactant-based gelling systems can avoid the damage to the formation caused by polymer-based fluids. Some viscoelastic surfactant-based gelling systems are disclosed in U.S. Pat. Nos. 5,979,557, 6,435,277, and 6,703,352 which have a common Assignee as the present application. The use of viscoelastic surfactant-based gelling systems to control leak-off is disclosed in U.S. Pat. No. 6,667,280 and U.S. Patent Application Publication No. 2003-0119680, which also have a common Assignee as the present application. Viscoelastic diverting acids (VDA's) were developed for carbonate matrix acidizing and have an initial nearly water-like viscosity, but after a considerable portion of the acid is spent, or consumed, in a carbonate formation that reacts with acid, viscosity increases substantially. Thus, when first injected, VDA's enter the most permeable zone(s), but when they gel, they block that zone or zones and divert subsequently injected fluid into previously less-permeable zones. The success of such systems depends upon the ability of the formation to react with a large amount of acid. Consequently, they are most useful with carbonates that have a large capacity to react with acid.
Although in situ gelation techniques are generally effective for controlling leakoff in the rock matrix and wormholes along the wellbore or fracture face, they are not particularly effective in controlling leakoff through natural fractures and/or into vugs. The relatively large natural fracture widths, conductivity, and volume render the conventional approaches either ineffective or inefficient, requiring a large volume of fluid to fill the natural fractures before reasonable fluid loss control can be achieved. This limitation has been observed when acidizing carbonate formations with large natural fractures; extremely large fluid volumes and multiple VDA stages are required before evidence of diversion is observed. It is, therefore, an object of embodiments of the present invention to provide a method for effectively controlling leakoff during oilfield treatments in naturally fractured formations.
It is known to use fibers to control fluid loss in solid laden fluids such as cement. Cement slurries containing a distribution of solid particles and glass fibers, for instance, have been pumped into the wellbore with the intention of depositing the particles and fibers in a mat at the fracture so as to physically block the fracture and reduce fluid loss. Similarly, fibers have been used in slickwater (water plus friction reducer) proppant fracturing treatments to assist in the transport of proppant along the fracture. However, the treatments have been known to screen out as soon as proppant stages containing fibers reach the formation. In such cases, where rock parameters and job design limited frac width, fibers were effective in bridging fractures that were less than about 0.25 cm (0.1 inches) in width.
Better methods of controlling leak off of treatment fluids into natural fractures are needed.